The invention relates to stimulation of wells penetrating subterranean formations. In particular it relates to acid fracturing; more particularly it relates to methods of etching the fracture faces so that etching is minimal in some regions but a conductive path from the fracture tip to the wellbore is nonetheless created. Most particularly it relates to a solid additive that is added to an aqueous fluid to provide an approximately neutral pH fracturing fluid that generates downhole a sandstone-dissolving fluid that provides differential etching of fracture faces.
In acid fracturing, acid is placed in the fracture, preferably along the entire distance from the fracture tip to the wellbore, so that it reacts with the face of the fracture to etch differential flow paths that a) create disparities so that the opposing fracture faces do not match up when the fracture pressure is released and so the fracture does not close completely, and b) provide flow paths for produced fluid along the fracture faces from distant portions of the fracture to the wellbore. Normally, the acid is placed in the desired location by forming an acidic fluid on the surface and pumping the acidic fluid from the surface and down the wellbore above fracture pressure. There are generally three major problems encountered during this normal procedure.
First, in the pumping operation the acid is in contact with iron-containing components of the wellbore such as casing, liner, coiled tubing, etc. Strong acids are corrosive to such materials, especially at high temperature. This means that corrosion inhibitors must be added to the fluid being injected in order not to limit the amount of acid, and/or the time of exposure, that can be used during injection of the acid. Furthermore, acid corrosion creates iron compounds such as iron chlorides. These iron compounds may precipitate, especially if sulfur or sulfides are present, and may interfere with the stability or effectiveness of other components of the fluid, thus requiring addition of iron control agents or iron sequestering agents to the fluid.
Second, if, as is usually the case, the intention is to use the acid to treat parts of the formation at a significant distance away from the wellbore (usually in addition to treating parts of the formation nearer the wellbore), this may be very difficult to accomplish because if an acid is injected from the surface down a wellbore and into contact with the formation, the acid will naturally react with the first reactive material with which it comes into contact. Depending upon the nature of the well and the nature of the treatment, this first-contacted and/or first-reacted material may be a filtercake, may be the formation surface forming the wall of an uncased (or openhole) wellbore, may be the near-wellbore formation, or may be a portion of the formation that has the highest permeability to the fluid, or is in fluid contact with a portion of the formation that has the highest permeability to the fluid. In many cases, this may not be the formation (matrix) material with which the operator wants the acid to react. At best this may be wasteful of acid; at worst this may make the treatment ineffective or even harmful. In general, the higher the temperature the more reactive is the acid and the greater are the problems. This is usually a severe problem when at least some of the formation is carbonate, which is typically very reactive towards acid.
Third, even when the acid has successfully been contacted with the desired region of the fracture face, there is sometimes a tendency for the acid to react evenly with the fracture faces, especially in localized regions, so that conductive channels along the fracture faces are not created by differential etching in such regions after fracture closure. This is most likely to occur when the rate of delivery of the acid to the reactive site (e.g. the fluid injection rate) is much lower than the rate of reaction of the acid.
There are several ways in which operators have dealt with these problems in the past. One method is to segregate the acid from the material with which reaction is not desired (such as wellbore metals or a near-wellbore reactive region of the formation). This is done, for example, by a) placing the acid in the internal phase of an emulsion (so-called “emulsified acid”) and then either causing or allowing the emulsion to invert at the time and place where reaction is desired or allowing slow transport of the acid across the phase boundaries, or b) encapsulating the acid, for example by the method described in U.S. Pat. No. 6,207,620, and then releasing the acid when and where it is needed. There are problems with these methods. Although emulsified acids are popular and effective, they require additional additives and specialized equipment and expertise, and may be difficult to control. A problem with the encapsulated acids is that the location and timing of release of the acid may be difficult to control. The release is brought about by either physical or chemical degradation of the coating. Physical damage to the encapsulating material, or incomplete or inadequate coating during manufacture, could cause premature release of the acid.
A second method is to delay formation of the acid. Templeton, et al., in “Higher pH Acid Stimulation Systems”, SPE paper 7892, 1979, described the hydrolysis of esters such as methyl formate and methyl acetate as in situ acid generators in the oilfield. They also described the reaction of ammonium monochloroacetic acid with water to generate glycolic acid and ammonium chloride in the oilfield. However, these acid precursors are liquids, and these reactions may take place rapidly as soon as the acid precursors contact water. A third method of encouraging differential etching is to fracture with a viscous non-acidic fluid and then to cause a less-viscous acid to finger through the viscous fluid.
There is a need for a method for acid fracturing of sandstones while minimizing the contact of acid with wellbore metals, minimizing contact of acid with the near wellbore formation early in the fracturing process, and creating highly conductive fractures along as much of the fracture length as possible; there is also a need for a solid non-acidic material that can be taken to a job site, added to water to produce a nearly neutral pH fluid slurry, and injected to provide the above results.